The present invention relates to the analysis of downhole fluids in a geological formation. More particularly, the invention relates to methods for validating a downhole formation fluid sample.
Schlumberger Technology Corporation, the assignee of this application, has provided a commercially successful borehole tool, the Modular Formation Dynamics Tester (MDT), which extracts and analyzes a flow stream of fluid from a formation in a manner substantially as set forth in co-owned U.S. Pat. Nos. 3,859,851 and 3,780,575 to Urbanosky. MDT is a trademark of Schlumberger. The Optical Fluid Analyzer (OFA), a component module of the MDT, determines the identity of the fluids in the MDT flow stream OFA is a trademark of Schlumberger.
Safinya, in U.S. Pat. No. 4,994,671, discloses a borehole apparatus which includes a testing chamber, means for directing a sample of fluid into the chamber, a light source preferably emitting near infrared rays and visible light, a spectral detector, a data base means, and a processing means. Fluids drawn from the formation into the testing chamber are analyzed by directing the light at the fluids, detecting the spectrum of the transmitted and/or back-scattered light, and processing the information accordingly. Prior art equipment is shown in FIGS. 1A-1C of U.S. Pat. No. 6,274,865-B1.
Because different fluid samples absorb energy differently, the fraction of incident light absorbed per unit of path length in the sample depends on the composition of the sample and the wavelength of the light. Thus, the amount of absorption as a function of the wavelength of the light, hereinafter referred to as the xe2x80x9cabsorption spectrumxe2x80x9d, has been used in the past as an indicator of the composition of the sample. For example, Safinya teaches that the absorption spectrum in the wavelength range of 0.3 to 2.5 microns can be used to analyze the composition of a fluid containing oil. The disclosed technique fits a plurality of data base spectra related to a plurality of oils and to water, etc., to the obtained absorption spectrum in order to determine the amounts of different oils and water that are present in the sample.
When the desired fluid is identified as flowing in the MDT, sample capture can begin and formation oil can be properly analyzed to determine important fluid properties needed to assess the economic value of the reserve, and to set various production parameters.
Mullins, in co-owned U.S. Pat. No. 5,266,800, teaches to distinguish formation oil from oil-based mud filtrate (OBM filtrate) by measuring OBM filtrate contamination using a coloration technique. By monitoring UV optical absorption spectrum of fluid samples obtained over time, a real time determination is made as to whether a formation oil is being obtained as opposed to OBM filtrate. Mullins discloses how the coloration of crude oils can be represented by a single parameter that varies over several orders of magnitude. The OFA was modified to include particular sensitivity towards the measurement of crude oil coloration, and thus OBM filtrate coloration. During initial extraction of fluid from the formation, OBM filtrate is present in relatively high concentration. Over time, as extraction proceeds, the OBM filtrate fraction declines and crude oil becomes predominant in the MDT flow line. Using coloration, as described in U.S. Pat. No. 5,266,800, this transition from contaminated to uncontaminated flow of crude oil can be monitored.
Shroer, in U.S. Pat. No. 6,274,865-B1, and in co-owned, co-pending U.S. application Ser. No. 09/300,190, teaches that the measured optical density of a downhole formation fluid sample contaminated by OBM filtrate changes slowly over time and approaches an asymptotic value corresponding to the true optical density of formation fluid. He further teaches the use of a real time log of OBM filtrate fraction to estimate OBM filtrate fraction by measuring optical density values at one or more frequencies, curve fitting to solve for an asymptotic value, and using the asymptotic value to calculate OBM filtrate fraction. He further teaches to predict future filtrate fraction as continued pumping flushes the region around the MDT substantially free of OBM filtrate. Thus, coloration can be used to distinguish crude oil from oil-based mud filtrate, current OBM filtrate fraction can be determined, and future OBM filtrate fraction can be predicted.
Tracers have been used previously in support of measurements carried out at the surface. Carrying samples to the surface for measurement has two disadvantages. First, there is the risk that the sample may be too contaminated to be of use, in which case the sampling process would have to be repeated. Second, if the sample is suitable for use, additional time may have been wasted flushing the sampling tool when earlier samples would have been good enough.
U.S. Pat. Nos. 3,780,575 and 3,859,851 to Urbanosky, U.S. Pat. Nos. 4,860,581 and 4,936,139 to Zimmerman et al., U.S. Pat. No. 4,994,671 to Safinya et al., U.S. Pat. Nos. 5,266,800 and 5,859,430 to Mullins, U.S. Pat. No. 6,274,865-B1 to Shroer et al., and U.S. application Ser. No. 09/300,190 are hereby incorporated herein by reference.
The invention provides a method for validating a downhole connate water sample drawn from formation surrounding a well, comprising: drilling the well with a water-based mud containing a water-soluble dye; obtaining a sample of formation fluid downhole; measuring optical density of the sample downhole; and validating the sample if sample optical density is acceptably low.
The invention provides a method for validating a downhole connate water sample in a well, comprising the acts of: (a) drilling the well with a water-based mud containing a water-soluble dye; (b) obtaining a sample of formation fluid downhole; (c) measuring optical density of the sample downhole; (d) repeating acts (b) and (c) to obtain optical density from each of a series of samples; and (e) validating a sample if sample optical density is acceptably low.
The invention provides a method for validating a downhole connate water sample drawn from formation surrounding a well, comprising: drilling the well with a water-based mud; obtaining a sample of formation fluid downhole; measuring at least one characteristic of downhole fluid indicative of water-based mud filtrate contamination levels in the sample; and validating the sample if the at least one measured characteristic is acceptably low.
The invention provides a method of determining when to collect a sample of downhole fluid drawn from a formation surrounding a well, comprising: measuring at least one characteristic of downhole fluid indicative of water-based mud filtrate contamination levels in downhole fluid drawn from a formation surrounding the well over a period of time; and using said measurements to determine when to collect a sample of said downhole fluid.